It is known to conduct enhanced oil recovery (EOR) of hydrocarbons from subterranean hydrocarbon-bearing formations after primary recovery processes are no longer feasible. Viscous, heavy oil, including bituminous deposits, can be too deep for surface recovery and in-situ methodologies are employed.
Thermal methods include such as in-situ combustion and steam flood, which use various arrangements of stimulation or injection wells and production wells. In some techniques the injection and production wells may serve both duties. Other techniques include cyclic steam stimulation (CSS), in-situ combustion and steam assisted gravity drainage (SAGD). SAGD uses closely coupled generally parallel wells, a horizontally-extending steam injection well forming a steam chamber for mobilizing heavy oil for recovery at a substantially parallel and horizontally-extending production well. Thermal in-situ approaches are typically applied for oilsands which are heavy and viscous, having a gravity of 8-10° API and viscosities ranging from 10,000 to 300,000 cp. Non-thermal approaches include Cold Heavy Oil Production with Sand (CHOPS) in which sand is co-produced with the heavy oil, the oil typically having viscosities in the range of 500 to 15000 cp. In Alberta, the Energy Resources Conservation Board (ERCB) has deemed or classified heavy oils by gravity as an ERCB Crude Oil Density (See directive 17 http://www.ercb.ca/docs/documents/directives/Directive017.pdf, as of October 2009, “crude bitumen wells and heavy oil wells density of 920 kilograms per cubic meter [kg/m3] or greater at 15° C.”). This specific gravity of about 0.92 is equivalent to about 22.3 API or heavier, while bitumen having a specific gravity of about 1.0 has an API gravity of about 10.
Where a heavy oil formation overlies a water zone, where the water forms a base of the formation, typically known as a basal water zone, in-situ techniques become more limited, in part due to the huge thermal heat sink of the water zone. One recovery approach which incorporated the water zone in the recovery was implemented by Shell Canada Limited and the Alberta Oilsands Technology and Research Authority (AOSTRA) in the late 1970's and 1980's in the Peace River leases of Alberta Canada. The approach was termed the pressure-cycle steam drive (PCSD). The PCSD utilized steam injection to heat the basal water zone underlying the oilsand. Once communication was established between wells, continuous steam injection was begun, with the injection and production rates controlled to alternately pressure up and blow down the reservoir (see Alberta Oil Sands Technology and Research Authority, AOSTRA Technical Handbook on Oil Sands, Bitumens and Heavy Oils. Edmonton, 1989). Shell Canada Limited set forth a historical review of resource recovery alternatives in their 2009 application to the Energy Resources Conservation Board (ERCB) of Alberta, CANADA, Carmon Creek Project. Reviewing their own PCSD concept, Shell stated: “steam is injected into the bottom water zone (the lowest 4 m to 6 m of the 25 m-thick reservoir) at high injection rates and pressures. Production rates at producers would vary between periods of low and high rates. This caused cycles of high reservoir pressure during low production rates and low reservoir pressure during high production rates. Expectations were that steam would be forced into the upper parts of the reservoir, and bitumen would be produced by gravity drainage. These expectations were not met during the large-scale development stage, and recovery was found to be uneconomic.”
Applicant understands that CSS techniques were subsequently employed to continue exploitation of this resource. CSS in this circumstance is still associated with difficulties. Typically, an upper injection well, for injecting steam and forming a steam chamber for mobilizing oil, and a lower producer well would have been provided for collecting heated, mobilized oil. The producer well is located about 5 m above the base of the oilsand formation and the injector well another about 5 m above the producer well. The location of the producer well, being about 5 m above the base, is known to be an arrangement to avoid or delay breakthrough from a thief zone or basal water zone. This also results in lost potential to exploit this lower 5 m of what might only be a 15 to 25 m thick zone. This and other thin payzones are still greatly underexploited.
Applicant believes the expense of surface steam production, only to be lost to the large heat sink of the water zone, contributed to the discontinuance of this methodology.
Another well known issue with underlying water zones is the tendency for water coning. The water, being more mobile, preferentially migrates to the production well to the exclusion of the oil resource.
Further, in thermal EOR, heat transfer to overburden has conventionally been an unfortunate energy loss.
Applicant believes that in-situ processes to date have not successfully accommodated due to energy losses and compromised as a result of underlying water. Further, some formations have had stimulation limited to cold production, such as heavy oil in unconsolidated sand, which can be situated in payzones too narrow for SAGD.
Improved techniques are required which recover more of the resource and with favourable economics.